U.S. patent number 9,759,062 [Application Number 14/434,736] was granted by the patent office on 2017-09-12 for telemetry system for wireless electro-acoustical transmission of data along a wellbore.
This patent grant is currently assigned to ExxonMobil Upstream Research Company. The grantee listed for this patent is Scott W. Clawson, Max Deffenbaugh, Mark M. Disko, Stuart R. Keller, Timothy I. Morrow, David A. Stiles, Katie M. Walker, Henry Alan Wolf. Invention is credited to Scott W. Clawson, Max Deffenbaugh, Mark M. Disko, Stuart R. Keller, Timothy I. Morrow, David A. Stiles, Katie M. Walker, Henry Alan Wolf.
United States Patent |
9,759,062 |
Deffenbaugh , et
al. |
September 12, 2017 |
Telemetry system for wireless electro-acoustical transmission of
data along a wellbore
Abstract
A system for downhole telemetry is provided herein. The system
employs a series of communications nodes spaced along a tubular
body either above or below ground, such as in a wellbore. The nodes
allow for wireless communication between one or more sensors
residing at the level of a subsurface formation or along a
pipeline, and a receiver at the surface. The communications nodes
employ electro-acoustic transducers that provide for node-to-node
communication along the tubular body at high data transmission
rates. A method of transmitting data in a wellbore is also provided
herein. The method uses a plurality of data transmission nodes
situated along a tubular body to accomplish a wireless transmission
of data along the wellbore using acoustic energy.
Inventors: |
Deffenbaugh; Max (Fulshear,
TX), Keller; Stuart R. (Houston, TX), Stiles; David
A. (Spring, TX), Morrow; Timothy I. (Humble, TX),
Disko; Mark M. (Glen Gardner, NJ), Wolf; Henry Alan
(Morris Plains, NJ), Walker; Katie M. (Milford, NJ),
Clawson; Scott W. (Califon, NJ) |
Applicant: |
Name |
City |
State |
Country |
Type |
Deffenbaugh; Max
Keller; Stuart R.
Stiles; David A.
Morrow; Timothy I.
Disko; Mark M.
Wolf; Henry Alan
Walker; Katie M.
Clawson; Scott W. |
Fulshear
Houston
Spring
Humble
Glen Gardner
Morris Plains
Milford
Califon |
TX
TX
TX
TX
NJ
NJ
NJ
NJ |
US
US
US
US
US
US
US
US |
|
|
Assignee: |
ExxonMobil Upstream Research
Company (Spring, TX)
|
Family
ID: |
50979174 |
Appl.
No.: |
14/434,736 |
Filed: |
December 18, 2013 |
PCT
Filed: |
December 18, 2013 |
PCT No.: |
PCT/US2013/076273 |
371(c)(1),(2),(4) Date: |
April 09, 2015 |
PCT
Pub. No.: |
WO2014/100264 |
PCT
Pub. Date: |
June 26, 2014 |
Prior Publication Data
|
|
|
|
Document
Identifier |
Publication Date |
|
US 20150275657 A1 |
Oct 1, 2015 |
|
Related U.S. Patent Documents
|
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
Issue Date |
|
|
61739414 |
Dec 19, 2012 |
|
|
|
|
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B
47/14 (20130101); E21B 47/16 (20130101) |
Current International
Class: |
B60Q
1/54 (20060101); G01V 3/00 (20060101); E21B
47/16 (20060101); E21B 47/14 (20060101) |
References Cited
[Referenced By]
U.S. Patent Documents
Foreign Patent Documents
|
|
|
|
|
|
|
0 636 763 |
|
Feb 1995 |
|
EP |
|
1 409 839 |
|
Apr 2005 |
|
EP |
|
WO 2010/074766 |
|
Jul 2010 |
|
WO |
|
WO 2013/079928 |
|
Jun 2013 |
|
WO |
|
WO 2013/079929 |
|
Jun 2013 |
|
WO |
|
WO 2013/112273 |
|
Aug 2013 |
|
WO |
|
WO 2014/018010 |
|
Jan 2014 |
|
WO |
|
WO 2014/049360 |
|
Apr 2014 |
|
WO |
|
WO 2014/134741 |
|
Sep 2014 |
|
WO |
|
Other References
Author: Department of Defense; Title: Interoperability and
Performance Standards for Medium and High Frequency Radio Systems;
Date: Mar. 1, 1999, Pertinent Pages: whole document. cited by
examiner .
Emerson Process Management (2011), "Roxar downhole Wireless PT
sensor system," www.roxar.com, or downhole@roxar.com, 2 pgs. cited
by applicant.
|
Primary Examiner: Lim; Steven
Assistant Examiner: Adnan; Muhammad
Attorney, Agent or Firm: ExxonMobil Upstream Research
Company--Law Department
Parent Case Text
CROSS-REFERENCE TO RELATED APPLICATIONS
This application is the National Stage of International Application
No. PCT/US2013/076273, filed 18 Dec. 2013, which claims the benefit
of U.S. Ser. No. 61/739,414, filed Dec. 19, 2012, the entire
contents of which are hereby incorporated by reference herein. This
application is also related to U.S. Ser. Nos. 61/739,679
(PCT/US2013/076282), 61/739,677 (PCT/US2013/076286), 61/739,678
(PCT/US2013/076284), and 61/739,681 (PCT/US2013/076278), each filed
on Dec. 19, 2012, the entire contents of each of which are also
hereby incorporated by reference herein.
Claims
What is claimed is:
1. An electro-acoustic system for wireless telemetry along a
tubular body, comprising: a tubular body fabricated from steel; at
least one sensor disposed along the tubular body; a sensor
communications node placed along the tubular body and connected to
a wall of the tubular body, the sensor communications node being in
electrical communication with the at least one sensor and
configured to receive signals from the at least one sensor, the
signals representing a parameter associated with a subsurface
location along the tubular body; a topside communications node
placed proximate a surface; a plurality of intermediate
communications nodes spaced along the tubular body and attached to
an outer wall of the tubular body, the intermediate communications
nodes configured to transmit acoustic waves from the sensor
communications node to the topside communications node in
node-to-node arrangement; and a receiver at the surface configured
to receive signals from the topside communications node; wherein
each of the intermediate communications nodes comprises: a sealed
housing; an independent power source residing within the housing;
an electro-acoustic transducer and associated transceiver also
residing within the housing designed to receive and re-transmit the
acoustic waves, thereby providing communications telemetry; wherein
each of the acoustic waves represents a packet of information
comprising a plurality of separate tones; and wherein at least one
of (i) the sensor communications node and (ii) at least one of the
plurality of intermediate communications node, is configured to:
(a) transmit a first acoustic tone at a selected frequency at a
frequency in a range of from 50-500 kHz for a first transmission
time, (b) receive the transmitted acoustic tone for a first
reverberation listening time that is greater than the first
transmission time, (c) transmit another acoustic tone at another
selected frequency at a frequency in a range of from 50-500 kHz for
at least one of the first transmission time and another
transmission time, (d) receive the another transmitted acoustic
tone for at least one of the first reverberation listening time and
another reverberation listening time, greater than the another
transmission time, (e) determine a dominant received frequency
based on the received acoustic tone for the first reverberation
listening time and the received another acoustic tone for at least
one of the first reverberation listening time and the another
reverberation listening time, and (f) transmit subsequent acoustic
waves from the sensor communications node to the topside
communications node in node-to-node arrangement using the dominant
frequency, wherein each intermediate communications node listens
for the acoustic waves generated for a longer time than the time
for which the acoustic waves were generated by a previous
intermediate communications node.
2. The electro-acoustic system of claim 1, wherein: the surface is
an earth surface; and the tubular body is a pipe residing below
ground.
3. The electro-acoustic system of claim 1, wherein: the surface is
a water surface; and the tubular body is a pipe residing below the
water surface.
4. The electro-acoustic system of claim 1, wherein: the tubular
body is comprised of pipe joints disposed in a wellbore, with the
wellbore penetrating into a subsurface formation; and the at least
one sensor and the sensor communications node are disposed along
the wellbore proximate a depth of the subsurface formation.
5. The electro-acoustic system of claim 4, wherein the parameter
comprises temperature, pressure, fluid flow, strain, or geological
information related to a rock matrix of the subsurface
formation.
6. The electro-acoustic system of claim 4, wherein the at least one
sensor comprises (i) a pressure sensor, (ii) a temperature sensor,
(iii) an induction log, (iv) a gamma ray log, (v) a formation
density sensor, (vi) a sonic velocity sensor, (vii) a vibration
sensor, (viii) a resistivity sensor, (ix) a flow meter, (x) a
microphone, (xi) a geophone, or (xii) a set of position
sensors.
7. The electro-acoustic system of claim 4, wherein: the tubular
body is a drill string; and each of the intermediate communications
nodes is removably attached to an outer surface of pipe joints
making up the drill string.
8. The electro-acoustic system of claim 4, wherein: the tubular
body is a casing string; at least some of the intermediate
communications nodes are surrounded by a cement sheath; and each of
the intermediate communications nodes is attached to an outer
surface of pipe joints making up the casing string.
9. The electro-acoustic system of claim 4, wherein: the tubular
body is a production tubing; and each of the intermediate
communications nodes is attached to an outer surface of pipe joints
making up the production tubing.
10. The electro-acoustic system of claim 9, wherein: a well head is
placed above the wellbore; and the topside communications node is
clamped (i) on an outer surface of the wellhead, or (ii) on the
outer surface of an uppermost joint of the production tubing.
11. The electro-acoustic system of claim 10, wherein: the surface
is a land surface or an offshore platform; and the signal from the
topside communications node to the receiver is transmitted via a
Class I, Division 1 conduit or is a wireless transmission.
12. The electro-acoustic system of claim 1, wherein the at least
one sensor: (i) resides in the housing of a sensor communications
node, or (ii) resides external to the sensor communications
node.
13. The electro-acoustic system of claim 1, wherein the at least
one sensor: resides in the housing of a sensor communications node;
and comprises an electro-acoustic transducer within the sensor
communications node.
14. The electro-acoustic system of claim 1, wherein the acoustic
waves provide data that is modulated by (i) a multiple frequency
shift keying method, (ii) a frequency shift keying method, (iii) a
multi-frequency signaling method, (iv) a phase shift keying method,
(v) a pulse position modulation method, or (vi) an on-off keying
method.
15. The electro-acoustic system of claim 1, wherein the
intermediate communications nodes are spaced apart according to the
length of the joints of pipe.
16. The electro-acoustic system of claim 1, wherein the
intermediate communications nodes are spaced at about 10 to about
100 foot intervals.
17. The electro-acoustic system of claim 1, wherein the
communications nodes transmit data representing the parameter at a
rate exceeding about 50 bps.
18. The electro-acoustic system of claim 1, wherein a frequency
band for the acoustic wave transmission is about 25 KHz wide.
19. The electro-acoustic system of claim 1, wherein the
transceivers listen for tones that are selected to be within a
frequency band where the signals are detectable at least two nodes
away from a transmitting node.
20. The electro-acoustic system of claim 1, wherein: the acoustic
waves provide data that is modulated by (i) a multiple frequency
shift keying method where each tone is selected from an alphabet of
at least 8 tones, representing four bits of information.
21. A method of transmitting data in a wellbore, comprising:
providing a sensor along the wellbore at a depth of a subsurface
formation; running joints of pipe into the wellbore, the joints of
pipe being connected by threaded couplings; attaching a series of
communications nodes to the joints of pipe according to a
predesignated spacing, wherein adjacent communications nodes are
configured to communicate by acoustic signals transmitted through
the joints of pipe, wherein each of the communications nodes
comprises: a sealed housing; an electro-acoustic transducer and
associated transceiver residing within the housing configured to
send and receive acoustic signals between nodes; and an independent
power source also residing within the housing for providing power
to the transceiver; providing a receiver at a surface; and sending
signals from the sensor and to the receiver at the surface via the
series of communications nodes, with the signals being indicative
of a subsurface condition; and using at least one of (i) the sensor
and (ii) at least one of the series of communications nodes to: (a)
transmit a first acoustic tone at a selected frequency at a
frequency in a range of from 50-500 kHz for a first transmission
time, (b) receive the transmitted acoustic tone for a first
reverberation listening time that is greater than the first
transmission time, (c) transmit another acoustic tone at another
selected frequency at a frequency in a range of from 50-500 kHz for
at least one of the first transmission time and another
transmission time, (d) receive the another transmitted acoustic
tone for at least one of the first reverberation listening time and
another reverberation listening time, greater than the another
transmission time; (e) determine a dominant received frequency
based on the received acoustic tone for the first reverberation
listening time and the received another acoustic tone for at least
one of the first reverberation listening time and the another
reverberation listening time, and (f) transmit subsequent acoustic
waves from the sensor communications node to the topside
communications node in node-to-node arrangement using the dominant
frequency, and (g) each intermediate communications node listens
for the acoustic waves generated for a longer time than the time
for which the acoustic waves were generated by a previous
intermediate communications node, wherein each intermediate
communications node listens for the acoustic waves generated for a
longer time than the time for which the acoustic waves were
generated by a previous intermediate communications node.
22. The method of claim 21, wherein the surface is an earth surface
or a water surface.
23. The method of claim 21, wherein the joints of pipe form a
string of drill pipe, a string of casing, or a string of production
tubing.
24. The method of claim 21, wherein the sensor is (i) a pressure
sensor, (ii) a temperature sensor, (iii) an induction log, (iv) a
gamma ray log, (v) a formation density sensor, (vi) a sonic
velocity sensor, (vii) a vibration sensor, (viii) a resistivity
sensor, (ix) a flow meter, (x) a microphone, (xi) a geophone, or
(xii) a set of position sensors.
25. The method of claim 21, wherein each of the communications
nodes further comprises at least one clamp for radially attaching
the intermediate communications node onto an outer surface of a
joint of pipe.
26. The method of claim 25, wherein the at least one clamp
comprises: a first arcuate section; a second arcuate section; a
hinge for pivotally connecting the first and second arcuate
sections; and a fastening mechanism for securing the first and
second arcuate sections around an outer surface of the tubular
body.
27. The method of claim 21, wherein: the electro-acoustic
transceivers receive acoustic waves at a frequency, and re-transmit
the acoustic waves at the same frequency; and the electro-acoustic
transceivers listen for the acoustic waves generated for a longer
time than the time for which the acoustic waves were generated by a
previous communications node.
28. The method of claim 21, wherein the sensor resides in the
housing of a sensor communications node.
29. The method of claim 21, wherein: the joints of pipe form a
casing string; at least some of the joints of pipe and the
communications nodes are surrounded by a cement sheath.
30. A method of transmitting data in a wellbore, comprising:
running a tubular body into the wellbore, the wellbore penetrating
into a subsurface formation and the tubular body being comprised of
pipe joints; placing at least one sensor along the wellbore at a
depth of the subsurface formation; attaching a sensor
communications node to a wall of the tubular body proximate the
depth of the subsurface formation, the sensor communications node
being in electrical communication with the at least one sensor and
configured to receive signals from the at least one sensor, the
signals representing a subsurface condition; providing a topside
communications node proximate a surface of the wellbore; and
attaching a plurality of intermediate communications nodes to a
wall of the tubular body in spaced-apart relation, the intermediate
communications nodes configured to transmit acoustic waves from the
sensor communications node to the topside communications node in
node-to-node arrangement; wherein each of the intermediate
communications nodes comprises: a sealed housing; an independent
power source residing within the housing; an electro-acoustic
transducer and associated transceiver also residing within the
housing designed to receive the acoustic waves and re-transmit them
after reverberation of the acoustic waves has substantially
attenuated, the acoustic waves correlating to the signals generated
by the sensor; and at least one clamp for radially attaching the
communications node onto an outer surface of the tubular body; and
using at least one of (i) the sensor communications node and (ii)
at least one of the plurality of communications nodes to: (a)
transmit a first acoustic tone at a selected frequency at a
frequency in a range of from 50-500 kHz for a first transmission
time, (b) receive the transmitted acoustic tone for a first
reverberation listening time that is greater than the first
transmission time, (c) transmit another acoustic tone at another
selected frequency at a frequency in a range of from 50-500 kHz for
at least one of the first transmission time and another
transmission time, (d) receive the another transmitted acoustic
tone for at least one of the first reverberation listening time and
a another reverberation listening time, greater than the another
transmission time; (e) determine a dominant received frequency
based on the received acoustic tone for the first reverberation
listening time and the received another acoustic tone for at least
one of the first reverberation listening time and the another
reverberation listening time, (f) transmit subsequent acoustic
waves from the sensor communications node to the topside
communications node in node-to-node arrangement using the dominant
frequency, and (g) each intermediate communications node listens
for the acoustic waves generated for a longer time than the time
for which the acoustic waves were generated by a previous
intermediate communications node.
31. The method of claim 30, wherein the communications nodes
transmit data representing the subsurface condition at a rate
exceeding about 50 bps.
32. The method of claim 30, wherein the tubular body forms a string
of drill pipe, a string of casing, a string of production tubing,
or a string of injection tubing.
33. The method of claim 32, further comprising: receiving signals
from the topside communications node at a receiver; and analyzing
the signals.
34. The method of claim 32, wherein: the tubular body comprises a
string of production tubing; a well head is placed above the
wellbore; and the topside communications node is attached to (i) an
outer surface of the well head, or (ii) the outer surface of an
uppermost joint of the production tubing.
35. The method of claim 33, wherein: the surface is a land surface
or an offshore platform; and the signal from the topside
communications node to the receiver is transmitted via (i) a Class
I, Division 1 conduit, or (ii) an electromagnetic (RF) wireless
connection.
36. The method of claim 30, wherein the at least one sensor
comprises (i) a pressure sensor, (ii) a temperature sensor, (iii)
an induction log, (iv) a gamma ray log, (v) a formation density
sensor, (vi) a sonic velocity sensor, (vii) a vibration sensor,
(viii) a resistivity sensor, (ix) a flow meter, (x) a microphone,
(xi) a geophone, or (xii) a set of position sensors.
37. The method of claim 30, wherein a frequency band for the
acoustic wave transmission operates from 100 kHz to 125 kHz.
38. The method of claim 37, wherein the electro-acoustic
transceiver for each of the intermediate communications nodes
receives the acoustic waves generated for a longer time than the
time for which the acoustic waves were generated by a previous
communications node.
39. The method of claim 30, wherein the step of attaching a
plurality of intermediate communications nodes to the tubular body
comprises clamping the intermediate communications nodes to an
outer surface of the tubular body.
40. A communications node system for downhole telemetry,
comprising: a tubular body having a pin end, a box end, and an
elongated wall between the pin end and the box end, with the
tubular body being fabricated from a steel material having a
resonance frequency; and a communications node comprising: a
housing also fabricated from a steel material, with the steel
material of the housing having a resonance frequency; a sealed bore
within the housing; an independent power source residing within the
bore; an electro-acoustic transducer and associated transceiver
also residing within the bore for receiving and transmitting
acoustic waves; and at least one clamp for radially clamping the
communications node onto an outer surface of the tubular body; and
a sensor communications node; and a plurality of intermediate
communications nodes; wherein at least one of the sensor
communications node and (ii) at least one of the plurality of
intermediate communication nodes, is configured to: (a) transmit a
first acoustic tone at a selected frequency at a frequency in a
range of from 50-500 kHz for a first transmission time, (b) receive
the transmitted acoustic tone for a first reverberation listening
time that is greater than the first transmission time, (c) transmit
another acoustic tone at another selected frequency at a frequency
in a range of from 50-500 kHz for at least one of the first
transmission time and another transmission time, (d) receive the
another transmitted acoustic tone for at least one of the first
reverberation listening time and a another reverberation listening
time, greater than the another transmission time, (e) determine a
dominant received frequency based on the received acoustic tone for
the first reverberation listening time and the received another
acoustic tone for at least one of the first reverberation listening
time and the another reverberation listening time, and (f) transmit
subsequent acoustic waves from the sensor communications node to
the topside communications node in node-to-node arrangement using
the dominant frequency, wherein each intermediate communications
node listens for the acoustic waves generated for a longer time
than the time for which the acoustic waves were generated by a
previous intermediate communications node.
41. The communications node system of claim 40, wherein the tubular
body is a joint of drill pipe, a joint of casing, a joint of
production tubing, or a joint of a liner string.
42. The communications node system of claim 40, wherein: the
housing of the communications node comprises a first end and a
second opposite end; and the at least clamp comprises a first clamp
secured at the first end of the housing, and a second clamp secured
at the second end of the housing.
43. The communications node system of claim 42, wherein the
communications node further comprises a first shoe at the first end
of the housing and a second shoe at the second end of the
housing.
44. The communications node system of claim 43, wherein the first
shoe and the second shoe each comprises: a beveled edge designed to
face away from the tubular body, a flat surface designed to face
towards the tubular body, and a shoulder providing a clearance
between the flat surface and the tubular body; and the flat surface
of each shoe is welded onto a respective clamp.
45. The communications node system of claim 40, wherein: the
transceiver is designed to receive acoustic waves, convert the
acoustic waves into an electrical signal, convert the electrical
signal into new acoustic waves, and re-transmit the new acoustic
waves at the same frequency; and the transceiver is configured to
transmit data representing a subsurface condition at a rate
exceeding about 50 bps.
46. The communications node system of claim 40, wherein a frequency
band for the acoustic wave transmission operates from 50 kHz to 500
kHz.
47. The electro-acoustic system according to claim 1, wherein the
wireless telemetry is achieved through transmission of a number of
tones including an initial tone and a final tone using a MFSK tonal
alphabet with a supplemental tone such that the final tone
transmitted is not repeated.
48. An electro-acoustic system for wireless telemetry along a
pipeline, comprising: a tubular body fabricated from steel; at
least one sensor disposed along the tubular body; a sensor
communications node placed along the tubular body and connected to
a wall of the tubular body, the sensor communications node being in
electrical communication with the at least one sensor and
configured to receive signals from the at least one sensor, the
signals representing a parameter associated with a location along
the tubular body; a proximal communications node placed at a
beginning location along the tubular body; a plurality of
intermediate communications nodes spaced along the tubular body and
attached to an outer wall of the tubular body, the intermediate
communications nodes configured to transmit acoustic waves from the
sensor communications node to the proximal communications node in
node-to-node arrangement; a receiver configured to receive signals
from the proximal communications node; wherein each of the
intermediate communications nodes comprises: a sealed housing; an
independent power source residing within the housing; an
electro-acoustic transducer and associated transceiver also
residing within the housing designed to receive and re-transmit the
acoustic waves, thereby providing communications telemetry; and
wherein at least one of (i) the sensor communications node and (ii)
at least one of the plurality of intermediate communications node,
is configured to: (a) transmit a first acoustic tone at a selected
frequency at a frequency in a range of from 50-500 kHz for a first
transmission time, (b) receive the transmitted acoustic tone for a
first reverberation listening time that is greater than the first
transmission time, (c) transmit another acoustic tone at another
selected frequency at a frequency in a range of from 50-500 kHz for
at least one of the first transmission time and another
transmission time, (d) receive the another transmitted acoustic
tone for at least one of the first reverberation listening time and
a another reverberation listening time, greater than the another
transmission time, (e) determine a dominant received frequency
based on the received acoustic tone for the first reverberation
listening time and the received another acoustic tone for at least
one of the first reverberation listening time and the another
reverberation listening time, and (f) transmit subsequent acoustic
waves from the sensor communications node to the topside
communications node in node-to-node arrangement using the dominant
frequency, wherein each intermediate communications node listens
for the acoustic waves generated for a longer time than the time
for which the acoustic waves were generated by a previous
intermediate communications node.
49. The electro-acoustic system of claim 48, wherein the at least
one sensor comprises (i) a pressure sensor, (ii) a temperature
sensor, (iii) a sonic velocity sensor, (iv) a vibration sensor, or
(v) a flow meter.
50. The electro-acoustic system of claim 48, wherein each of the
intermediate communications nodes further comprises at least one
clamp for radially attaching the communications node onto an outer
surface of the tubular body.
Description
BACKGROUND OF THE INVENTION
This section is intended to introduce various aspects of the art,
which may be associated with exemplary embodiments of the present
disclosure. This discussion is believed to assist in providing a
framework to facilitate a better understanding of particular
aspects of the present disclosure. Accordingly, it should be
understood that this section should be read in this light, and not
necessarily as admissions of prior art.
FIELD OF THE INVENTION
The present invention relates to the field of data transmission
along a tubular body, such as a steel pipe. More specifically, the
invention relates to the transmission of data along a pipe within a
wellbore or along a pipeline, either at the surface or in a body of
water. The present invention further relates to a wireless
transmission system for transmitting data up a drill string during
a drilling operation or along the casing during drilling or
production operations.
General Discussion of Technology
It is desirable to transmit data along a pipeline without the need
for wires or radio frequency (electromagnetic) communications
devices. Examples abound where the installation of wires is either
technically difficult or economically impractical. The use of radio
transmission may also be impractical or unavailable in cases where
radio-activated blasting is occurring, or where the attenuation of
radio waves near the tubular body is significant.
Likewise, it is desirable to collect and transmit data along a
tubular body in a wellbore, such as during a drilling process. In
the drilling of oil and gas wells, a wellbore is formed using a
drill bit that is urged downwardly at a lower end of a drill
string. The drill bit is rotated while force is applied through the
drill string and against the rock face of the formation being
drilled. During this process, the operator may seek to acquire real
time data related to temperature, pressure, rate of rock
penetration, inclination, azimuth, fluid composition, and local
geology. In order to obtain such information, special downhole
assemblies have been developed. These assemblies are generally
referred to as Logging While Drilling (LWD) or Measurement While
Drilling (MWD) assemblies, or generically as bottom hole
assemblies.
LWD and MWD assemblies are typically placed proximate the drill bit
at the bottom of the drill string. Bottom hole assemblies having
LWD or MWD capabilities are able to store or transmit information
about subsurface conditions for review by drilling or production
operators at the surface. LWD and MWD techniques generally seek to
reduce the need for tripping the drill string and running wireline
logs to obtain downhole data.
A variety of technologies have been proposed or developed for
downhole communications using LWD or MWD. In one form, MWD and LWD
information is simply stored in a processor having memory. The
processor is retrieved and the information is downloaded later when
the drill string is pulled, such as when a drill bit is changed out
or a new bottom hole assembly is installed.
Several real time data telemetry systems have also been offered.
One involves the use of a physical cable such as an electrical
conductor or a fiber optic cable that is secured to the tubular
body. The cable may be secured to either the inner or the outer
diameter of the pipe. The cable provides a hard wire connection
that allows for real-time transmission of data and the immediate
evaluation of subsurface conditions. Further, these cables allow
for high data transmission rates and the delivery of electrical
power directly to downhole sensors.
It can be readily perceived that the placement of a physical cable
along a string of drill pipe during drilling is problematic. In
this respect, the cable will become quickly tangled and will break
if secured along a rotating drill string. This problem is lessened
when a downhole mud motor is used that allows for a generally
non-rotating drill pipe. However, even in this instance the harsh
downhole environment and the considerable force of the pipe as it
scrapes across the surrounding borehole can impair the cable.
It has been proposed to place a physical cable along the outside of
a casing string during well completion. However, this can be
difficult as the placement of wires along a pipe string requires
that thousands of feet of cable be carefully unspooled and fed
during pipe connection and run-in. Further, the use of hard wires
in a well completion requires the installation of a
specially-designed well head that includes through-openings for the
wires. In addition, if the wire runs outside of a casing string,
this creates a potential weak spot in the cement sheath that may
contribute to a loss of pressure isolation between subsurface
intervals. It is generally not feasible to pass wires through a
casing mandrel for subsea applications. In sum, passing cable in
the annulus adds significant cost, both for equipment and for rig
time, to well completions.
Mud pulse telemetry, or mud pressure pulse transmission, is
commonly used during drilling to obtain data from sensors at or
near the drill bit. Mud pulse telemetry employs variations in
pressure in the drilling mud to transmit signals from the bottom
hole assembly to the surface. The variations in pressure may be
sensed and analyzed by a computer at the surface.
A downside to mud pulse telemetry is that it transmits data to the
surface at relatively slow rates, typically at rates of less than
20 bits per second (bps). This rate decreases as the length of the
wellbore increases, even down to 10 or fewer bps. Slow data
transmission rates can be costly to the drilling process. For
example, the time it takes to downlink instructions and uplink
survey data (such as azimuth and inclination), during which the
drill string is normally held stationary, can be two to seven
minutes. Since many survey stations are typically required, this
downlink/uplink time can be very expensive, especially on deepwater
rigs where daily operational rates can exceed $2 million.
Similarly, the time it takes to downlink instructions and uplink
data associated with many other tasks such as setting parameters in
a rotary steerable directional drilling tool or obtaining a
pressure reading from a pore-pressure-while-drilling tool can be
very costly.
The use of acoustic telemetry has also been suggested. Acoustic
telemetry employs an acoustic signal generated at or near the
bottom hole assembly or bottom of a pipe string. The signal is
transmitted through the wellbore pipe, meaning that the pipe
becomes the carrier medium for sound waves. Transmitted sound waves
are detected by a receiver and converted to electrical signals for
analysis.
U.S. Pat. No. 5,924,499 entitled "Acoustic Data Link and Formation
Property Sensor for Downhole MWD System" teaches the use of
acoustic signals for "short hopping" a component along a drill
string. Signals are transmitted from the drill bit or from a
near-bit sub and across the mud motors. This may be done by sending
separate acoustic signals simultaneously--one that is sent through
the drill string, a second that is sent through the drilling mud,
and optionally, a third that is sent through the formation. These
signals are then processed to extract readable signals.
U.S. Pat. No. 6,912,177, entitled "Transmission of Data in
Boreholes," addresses the use of an acoustic transmitter that is
part of a downhole tool. Here, the transmitter is provided adjacent
a downhole obstruction such as a shut-in valve along a drill stem
so that an electrical signal may be sent across the drill stem.
U.S. Pat. No. 6,899,178, entitled "Method and System for Wireless
Communications for Downhole Applications," describes the use of a
"wireless tool transceiver" that utilizes acoustic signaling. Here,
an acoustic transceiver is in a dedicated tubular body that is
integral with a gauge and/or sensor. This is described as part of a
well completion.
Faster data transmission rates with some level of clarity have been
accomplished using electromagnetic (EM) telemetry. EM telemetry
employs electromagnetic waves, or alternating current magnetic
fields, to "jump" across pipe joints. In practice, a
specially-milled drill pipe is provided that has a conductor wire
machined along an inner diameter. The conductor wire transmits
signals to an induction coil at the end of the pipe. The induction
coil, in turn, transmits an EM signal to another induction coil,
which sends that signal through the conductor wire in the next
pipe. Thus, each threaded connection provides a pair of specially
milled pipe ends for EM communication.
National Oilwell Varco.RTM. of Houston, Tex. offers a drill pipe
network, referred to as IntelliSery.RTM., that uses EM telemetry.
The IntelliServ.RTM. system employs drill pipe having integral
wires that can transmit LWD/MWD data to the surface at speeds of up
to 1 Mbps. This creates a communications system from the drill
string itself. The IntelliServ.RTM. communications system uses an
induction coil built into both the threaded box and pin ends of the
drill pipe joints so that data may be transmitted across each
connection. Examples of IntelliServ.RTM. patents are U.S. Pat. No.
7,277,026 entitled "Downhole Component With Multiple Transmission
Elements," and U.S. Pat. No. 6,670,880 entitled "Downhole Data
Transmission System."
It is observed that the induction coils in an EM telemetry system
must be precisely located in the box and pin ends of the joints of
the drill string to ensure reliable data transfer. For a long
(e.g., 20,000 foot) well, there can be more than 600 tool joints.
This represents over 600 pipe sections to be threadedly connected.
Further, each threaded connection is preferably tested at the
drilling platform to ensure proper functioning.
National Oilwell Varco.RTM. promotes its IntelliServ.RTM. system as
providing the oil and gas industry's "only high-speed, high-volume,
high-definition, bi-directional broadband data transmission system
that enables downhole conditions to be measured, evaluated,
monitored and actuated in real time." However, the IntelliServ.RTM.
system generally requires the use of booster assemblies along the
drill string. These can be three to six foot sub joints having a
diameter greater than the drill pipe placed in the drill string.
The booster assemblies, referred to sometimes as "signal
repeaters," are located along the drill pipe about every 1,500
feet. The need for repeaters coupled with the need for
specially-milled pipe can make the IntelliServ.RTM. system a very
expensive option.
Recently, the use of radiofrequency signals has been suggested.
This is offered in U.S. Pat. No. 8,242,928 entitled "Reliable
Downhole Data Transmission System." This patent suggests the use of
electrodes placed in the pin and box ends of pipe joints. The
electrodes are tuned to receive RF signals that are transmitted
along the pipe joints having a conductor material placed there
along, with the conductor material being protected by a special
insulative coating.
While high data transmission rates can be accomplished using RF
signals in a downhole environment, the transmission range is
typically limited to a few meters. This, in turn, requires the use
of numerous repeaters.
Accordingly, a need exists for a high speed wireless transmission
system in a wellbore that does not require the machining of
induction coils with precise grooves placed into pipe ends or the
need for electrodes in the pipe ends or couplings. Further, a need
exists for such a wireless transmission system that does not
require the precise alignment of induction coils or the placement
of RF electrodes between pipe joints.
SUMMARY OF THE INVENTION
A system for downhole telemetry is provided herein. The system
employs a series of autonomous communications nodes spaced along a
wellbore. The nodes allow for wireless communication between one or
more sensors residing at the level of a subsurface formation, and a
receiver at the surface.
The system first includes a tubular body disposed in the wellbore.
Where the wellbore is being formed, the tubular body is a drill
string, with the wellbore progressively penetrating into a
subsurface formation. The subsurface formation preferably
represents a rock matrix having hydrocarbon fluids available for
production in commercially acceptable volumes. Thus, the wellbore
is to be completed as a production well, or "producer."
Alternatively, the wellbore is to be completed as an injection well
or a formation monitoring well.
In another aspect, the wellbore has already been completed. The
tubular body is then a casing string or, alternatively, a
production string such as tubing.
The system also includes at least one sensor. As noted, the sensor
is disposed along the wellbore at a depth of the subsurface
formation. The sensor may be, for example, a temperature sensor, a
pressure sensor, a microphone, a geophone, a vibration sensor, a
resistivity sensor, a fluid flow measurement device, a formation
density sensor, a fluid identification sensor, or a strain gauge.
Where the wellbore is being drilled, the sensor may alternatively
be a set of position sensors indicating, inclination, azimuth, and
orientation.
The system further has a sensor communications node. The sensor
communications node is placed along the wellbore. The sensor
communications node is connected to the tubular body at the depth
of the subsurface formation. The sensor communications node is in
electrical communication with the at least one sensor. Preferably,
the sensor resides within a housing of the sensor communications
node.
The sensor communications node is configured to receive signals
from the at least one sensor. The signals represent a subsurface
condition such as temperature, pressure, or logging information.
The sensor communications node preferably includes a sealed housing
for holding the electronics.
The system also comprises a topside communications node. The
topside communications node is placed along the wellbore proximate
the surface. In one aspect, the topside communications node is
connected to the well head. The surface may be an earth surface.
Alternatively, in a subsea context, the surface may be an offshore
drilling or production platform.
The system further includes a plurality of intermediate
communications nodes. The intermediate communications nodes are
attached to the tubular body in spaced-apart relation. In one
aspect, the intermediate communications nodes are spaced at about
10 to about 100 foot (.about.3 meter to .about.30 meter) intervals.
The intermediate communications nodes are configured to relay
messages between from the sensor communications node and the
topside communications node.
Each of the intermediate communications nodes has an independent
power source. The power source may be, for example, batteries or a
fuel cell. In addition, each of the intermediate communications
nodes has an electro-acoustic transducer and associated transceiver
that is used to establish telemetry. The transceiver is designed to
receive and transmit acoustic waves at a frequency range enabling
(i) node-to-node acoustic transmission and (ii) a modulation scheme
permitting the transfer of information. In any aspect, each of the
acoustic waves represents a packet of information comprising a
plurality of separate tones, with each tone having a non-prescribed
amplitude, a non-prescribed reverberation time, or both.
The acoustic waves represent the readings taken and data generated
by the sensor. In this way, data about subsurface conditions are
transmitted wirelessly from node-to-node up to the surface. In one
aspect, the communications nodes transmit data as mechanical waves
at a rate exceeding about 50 bps. In a preferred embodiment,
multiple frequency shift keying (MFSK) is the modulation scheme
enabling the transmission of information.
A method of transmitting data in a wellbore is also provided
herein. The method uses a plurality of data transmission nodes
situated along a tubular body to accomplish a wireless transmission
of data along the wellbore. The wellbore penetrates into a
subsurface formation, allowing for the communication of a wellbore
condition at the level of the subsurface formation up to the
surface.
The method first includes running a tubular body into the wellbore.
The tubular body is formed by connecting a series of pipe joints
end-to-end.
The method also includes placing at least one sensor along the
wellbore at a depth of the subsurface formation. The sensor may be
a pressure sensor, a temperature sensor, a set of position sensors,
a vibration sensor, a formation density sensor, a strain gauge, a
sonic velocity sensor, a resistivity sensor, or other sensor.
The method further includes attaching a sensor communications node
to the tubular body. The sensor communications node is then placed
at the depth of the subsurface formation. The sensor communications
node is in electrical (or, optionally, optical) communication with
the at least one sensor. This communication may be by means of a
short wired connection. In one aspect, the sensor resides in the
housing of a sensor communications node.
The sensor communications node is configured to receive signals
from the at least one sensor. The signals represent a subsurface
condition as detected by the sensor. In one embodiment, the sensor
is the same electro-acoustic transducer that enables the telemetry
communication. In this way, amplitude and amplitude attenuation
values may be analyzed.
The method also provides for attaching a topside communications
node to the tubular body or other structure, such as the well head
or the blow out preventer (BOP), that is connected to the tubular
body. The topside communications node is attached to the tubular
body proximate the surface.
The method further comprises attaching a plurality of intermediate
communications nodes to the tubular body. The intermediate
communications nodes reside in spaced-apart relation along the
tubular body between the sensor communications node and the topside
communications node. The intermediate communications nodes are
configured to relay sensor data via acoustic waves from the sensor
communications node to the topside node. The intermediate
communications nodes are configured as described above.
In a preferred embodiment, the attaching steps comprise clamping
the various communications nodes, that is, at least the sensor
communications nodes and the intermediate communications nodes, to
the tubular body. These communications nodes are welded or
otherwise pre-attached to one or more clamps, which are then
secured around the tubular body during run-in.
In one aspect, the method further includes receiving a signal from
the topside communications node at a receiver. The receiver is
located at or just above the surface. The receiver preferably
receives electrical or optical signals from the topside
communications node. In one embodiment, the electrical or optical
signals are conveyed in a conduit suitable for operation in an
electrically classified area, that is, via a so-called "Class I,
Division 1" conduit (as defined by NFPA 497 and API 500).
Alternatively, data can be transferred from the topside
communications node to a receiver via an electromagnetic (RF)
wireless connection. The electrical signals may then be processed
and analyzed at the surface.
BRIEF DESCRIPTION OF THE DRAWINGS
So that the present inventions can be better understood, certain
drawings, charts, graphs and/or flow charts are appended hereto. It
is to be noted, however, that the drawings illustrate only selected
embodiments of the inventions and are therefore not to be
considered limiting of scope, for the inventions may admit to other
equally effective embodiments and applications.
FIG. 1 is a side, cross-sectional view of an illustrative wellbore.
The wellbore is being formed using a derrick, a drill string and a
bottom hole assembly. A series of communications nodes is placed
along the drill string as part of a telemetry system.
FIG. 2 is a cross-sectional view of a wellbore having been
completed. The illustrative wellbore has been completed as a cased
hole completion. A series of communications nodes is placed along a
tubing string as part of a telemetry system.
FIG. 3 is a perspective view of an illustrative pipe joint. A
communications node (such as a sensor communications node or an
intermediate communications node) of the present invention, in one
embodiment, is shown exploded away from the pipe joint.
FIG. 4A is a perspective view of a communications node as may be
used in the wireless data transmission system of the present
invention, in an alternate embodiment.
FIG. 4B is a cross-sectional view of the communications node of
FIG. 4A. The view is taken along the longitudinal axis of the node.
Here, a sensor is provided within the communications node.
FIG. 4C is another cross-sectional view of the communications node
of FIG. 4A. The view is again taken along the longitudinal axis of
the node. Here, a sensor resides along the wellbore external to the
communications node.
FIGS. 5A and 5B are perspective views of a shoe as may be used on
opposing ends of the communications node of FIG. 4A, in one
embodiment. In FIG. 5A, the leading edge, or front, of the shoe is
seen. In FIG. 5B, the back of the shoe is seen.
FIG. 6 is a perspective view of a communications node system of the
present invention, in one embodiment. The communications node
system utilizes a pair of clamps for connecting a communications
node onto a tubular body.
FIG. 7 is a flowchart demonstrating steps of a method for
transmitting data in a wellbore in accordance with the present
inventions, in one embodiment.
DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS
Definitions
As used herein, the term "hydrocarbon" refers to an organic
compound that includes primarily, if not exclusively, the elements
hydrogen and carbon. Examples of hydrocarbons include any form of
natural gas, oil, coal, and bitumen that can be used as a fuel or
upgraded into a fuel.
As used herein, the term "hydrocarbon fluids" refers to a
hydrocarbon or mixtures of hydrocarbons that are gases or liquids.
For example, hydrocarbon fluids may include a hydrocarbon or
mixtures of hydrocarbons that are gases or liquids at formation
conditions, at processing conditions, or at ambient conditions
(20.degree. C. and 1 atm pressure). Hydrocarbon fluids may include,
for example, oil, natural gas, gas condensates, coal bed methane,
shale oil, shale gas, and other hydrocarbons that are in a gaseous
or liquid state.
As used herein, the term "subsurface" refers to regions below the
earth's surface.
As used herein, the term "sensor" includes any electrical sensing
device or gauge. The sensor may be capable of monitoring or
detecting pressure, temperature, fluid flow, vibration,
resistivity, or other formation data.
As used herein, the term "formation" refers to any definable
subsurface region. The formation may contain one or more
hydrocarbon-containing layers, one or more non-hydrocarbon
containing layers, an overburden, and/or an underburden of any
geologic formation.
The terms "zone" or "zone of interest" refer to a portion of a
formation containing hydrocarbons. The term "hydrocarbon-bearing
formation" may alternatively be used.
As used herein, the term "wellbore" refers to a hole in the
subsurface made by drilling or insertion of a conduit into the
subsurface. A wellbore may have a substantially circular cross
section, or other cross-sectional shape. As used herein, the term
"well," when referring to an opening in the formation, may be used
interchangeably with the term "wellbore."
The terms "tubular member" or "tubular body" refer to any pipe,
such as a joint of casing, a portion of a liner, a drill string, a
production tubing, an injection tubing, a pup joint, a buried
pipeline, underwater piping, or above-ground pipeline. The tubular
body may also be a downhole tubular device such as a joint of sand
screen having a base pipe with pre-drilled holes, a slotted liner,
or an inflow control device.
Description of Selected Specific Embodiments
The inventions are described herein in connection with certain
specific embodiments. However, to the extent that the following
detailed description is specific to a particular embodiment or a
particular use, such is intended to be illustrative only and is not
to be construed as limiting the scope of the inventions.
FIG. 1 is a side, cross-sectional view of an illustrative well site
100. The well site 100 includes a derrick 120 at an earth surface
101, and a wellbore 150 extending from the earth surface 101 into
an earth subsurface 155. The wellbore 150 is being formed using the
derrick 120, a drill string 160 below the derrick 120, and a bottom
hole assembly 170 at a lower end of the drill string 160.
Referring first to the derrick 120, the derrick 120 includes a
frame structure 121 that extends up from the earth surface 101 and
which supports drilling equipment. The derrick 120 also includes a
traveling block 122, a crown block 123 and a swivel 124. A
so-called kelly 125 is attached to the swivel 124. The kelly 125
has a longitudinally extending bore (not shown) in fluid
communication with a kelly hose 126. The kelly hose 126, also known
as a mud hose, is a flexible, steel-reinforced, high-pressure hose
that delivers drilling fluid through the bore of the kelly 125 and
down into the drill string 160.
The kelly 125 includes a drive section 127. The drive section 127
is non-circular in cross-section and conforms to an opening 128
longitudinally extending through a kelly drive bushing 129. The
kelly drive bushing 129 is part of a rotary table. The rotary table
is a mechanically driven device that provides clockwise (as viewed
from above) rotational force to the kelly 125 and connected drill
string 160 to facilitate the process of drilling a borehole 105.
Both linear and rotational movement may thus be imparted from the
kelly 125 to the drill string 160.
A platform 102 is provided for the derrick 120. The platform 102
extends above the earth surface 101. The platform 102 generally
supports rig hands along with various components of drilling
equipment such as a pumps, motors, gauges, a dope bucket, pipe
lifting equipment and control equipment. The platform 102 also
supports the rotary table.
It is understood that the platform 102 shown in FIG. 1 is somewhat
schematic. It is also understood that the platform 102 is merely
illustrative and that many designs for drilling rigs, both for
onshore and for offshore operations, exist. The claims provided
herein are not limited by the configuration and features of the
drilling rig unless expressly stated in the claims.
Placed below the platform 102 and the kelly drive section 127 but
above the earth surface 101 is a blow-out preventer, or BOP 130.
The BOP 130 is a large, specialized valve or set of valves used to
control pressures during the drilling of oil and gas wells.
Specifically, blowout preventers control the fluctuating pressures
emanating from subterranean formations during a drilling process.
The BOP 130 may include upper 132 and lower 134 rams used to
isolate flow on the back side of the drill string 160. Blowout
preventers 130 also prevent the pipe joints making up the drill
string 160 and the drilling fluid from being blown out of the
wellbore 150 when a blowout threatens.
As shown in FIG. 1, the wellbore 150 is being formed down into the
subsurface formation 155. In addition, the wellbore 150 is being
shown as a deviated wellbore. Of course, this is merely
illustrative as the wellbore 150 may be a vertical well or even a
horizontal well, as shown later in FIG. 2.
In drilling the wellbore 150, a first string of casing 110 is
placed down from the surface 101. This is known as surface casing
110 or, in some instances (particularly offshore), conductor pipe.
The surface casing 110 is secured within the formation 155 by a
cement sheath. The cement sheath resides within an annular region
115 between the surface casing 110 and the surrounding formation
155.
During the process of drilling and completing the wellbore 150,
additional strings of casing (not shown) will be provided. These
may include intermediate casing strings and a final production
casing string. For the final production casing, a liner may be
employed, that is, a string of casing that is not tied back to the
surface 101.
As noted, the wellbore 150 is formed by using a bottom hole
assembly 170. The bottom-hole assembly 170 allows the operator to
control or "steer" the direction or orientation of the wellbore 150
as it is formed. In this instance, the bottom hole assembly 170 is
known as a rotary steerable drilling system, or RSS.
The bottom hole assembly 170 will include a drill bit 172. The
drill bit 172 may be turned by rotating the drill string 160 from
the platform 102. Alternatively, the drill bit 172 may be turned by
using so-called mud motors 174. The mud motors 174 are mechanically
coupled to and turn the nearby drill bit 172. The mud motors 174
are used with stabilizers or bent subs 176 to impart an angular
deviation to the drill bit 172. This, in turn, deviates the well
from its previous path in the desired azimuth and inclination.
There are several advantages to directional drilling. These
primarily include the ability to complete a wellbore along a
substantially horizontal axis of a subsurface formation, thereby
exposing a substantially greater formation face. These also include
the ability to penetrate into subsurface formations that are not
located directly below the wellhead. This is particularly
beneficial where an oil reservoir is located under an urban area or
under a large body of water. Another benefit of directional
drilling is the ability to group multiple wellheads on a single
platform, such as for offshore drilling. Finally, directional
drilling enables multiple laterals and/or sidetracks to be drilled
from a single wellbore in order to maximize reservoir exposure and
recovery of hydrocarbons.
The illustrative well site 100 also includes a sensor 178. Here,
the sensor 178 is part of the bottom hole assembly 170. The sensor
178 may be, for example, a set of position sensors that is part of
the electronics for a RSS. Alternatively or in addition, the sensor
178 may be a temperature sensor, a pressure sensor, or other sensor
for detecting a downhole condition during drilling. Alternatively
still, the sensor may be an induction log or gamma ray log or other
log that detects fluid and/or geology downhole.
The sensor 178 is part of a MWD or a LWD assembly. It is observed
that the sensor 178 is located above the mud motors 174. This is a
common practice for MWD assemblies. This allows the electronic
components of the sensor 178 to be spaced apart from the high
vibration and centrifugal forces acting on the bit 172.
Where the sensor 178 is a set of position sensors, the sensors may
include three inclinometer sensors and three environmental
acceleration sensors. Ideally, a temperature sensor and a wear
sensor will also be placed in the drill bit 172. These signals are
input into a multiplexer and transmitted.
It is desirable to send signals about the downhole condition back
to an operator at the surface 101. To do this, a telemetry system
is used. As discussed above, various telemetry systems are known in
the industry. However, the well site 100 of FIG. 1 presents a
telemetry system that utilizes a series of novel communications
nodes 180 placed along the drill string 160. These nodes 180 allow
for the high speed transmission of wireless signals based on the in
situ generation of acoustic waves.
The nodes first include a topside communications node 182. The
topside communications node 182 is placed closest to the surface
101. The topside node 182 is configured to receive and/or transmit
acoustic signals. The topside communications node can be below
grade as shown above, or above grade.
The nodes may also include a sensor communications node 184. The
sensor communications node is placed closest to the sensor 178. The
sensor communications node 184 is configured to communicate with
the downhole sensor 178, and then send a wireless signal using an
acoustic wave.
Finally, the nodes include a plurality of intermediate
communications nodes 180. Each of the intermediate communications
nodes 180 resides between the sensor node 182 and the topside node
184. The intermediate communications nodes 180 are configured to
receive and then relay acoustic signals along the length of the
wellbore 150. Preferably, the intermediate communications nodes 180
utilize two-way electro-acoustic transducers to both receive and
relay mechanical waves.
In FIG. 1, the nodes 180 are shown schematically. However, FIG. 3
offers an enlarged perspective view of an illustrative pipe joint
300, along with an illustrative intermediate communications node
350. The illustrative communications node 350 is shown exploded
away from the pipe joint 300.
In FIG. 3, the pipe joint 300 is intended to represent a joint of
drill pipe. However, the pipe joint 300 may be any other tubular
body such as a joint of tubing or a portion of pipeline. The pipe
joint 300 has an elongated wall 310 defining an internal bore 315.
The bore 315 transmits drilling fluids such as an oil based mud, or
OBM, during a drilling operation. The pipe joint 300 has a box end
322 having internal threads, and a pin end 324 having external
threads.
As noted, an illustrative intermediate communications node 350 is
shown exploded away from the pipe joint 300. The communications
node 350 is designed to attach to the wall 310 of the pipe joint
300 at a selected location. In one aspect, selected pipe joints 300
will each have an intermediate communications node 350 between the
box end 322 and the pin end 324. In one arrangement, the
communications node 350 is placed immediately adjacent the box end
322 or, alternatively, immediately adjacent the pin end 324 of
every joint of pipe. In another arrangement, the communications
node 350 is placed at a selected location along every second or
every third pipe joint 300 in a drill string 160. In other aspects,
more or less than one intermediate communications node may be
placed per joint 300.
The intermediate communications node 350 shown in FIG. 3 is
designed to be pre-welded onto the wall 310 of the pipe joint 300.
However, it is preferred that the communications node 350 be
configured to be selectively attachable to/detachable from a pipe
joint 300 by mechanical means at a well site. This may be done, for
example, through the use of clamps. Such a clamping system is shown
at 600 in FIG. 6, described more fully below. Alternatively, an
epoxy or other suitable acoustic couplant may be used for chemical
bonding. In any instance, the communications node 350 is an
independent wireless communications device that is designed to be
attached to an external surface of a well pipe.
There are several benefits to the use of an externally-placed
communications node that uses acoustic waves. For example, such a
node will not interfere with the flow of fluids within the internal
bore 315 of the pipe joint 300. Further, installation and
mechanical attachment can be readily assessed or adjusted, as
necessary.
In FIG. 3, the intermediate communications node 350 includes an
elongated body 351. The body 351 supports one or more batteries,
shown schematically at 352. The body 351 also supports an
electro-acoustic transducer, shown schematically at 354. In a
preferred embodiment, the electro-acoustic transducer 354 may be a
two-way transceiver that can both receive and transmit acoustic
signals. The communications node 350 is intended to represent the
communications nodes 180 of FIG. 1, in one embodiment. The two-way
electro-acoustic transducer 354 in each node 180 allows acoustic
signals to be sent from node-to-node, either up the wellbore 150 or
down the wellbore 150.
Returning to FIG. 1, in operation, the sensor communications node
184 is in electrical communication with the sensor 178. This may be
by means of a short wire, or by means of wireless communication
such as infrared or radio-frequency communication. The sensor
communications node 184 is configured to receive signals from the
sensor 178, wherein the signals represent a subsurface condition
such as position, temperature, pressure, resistivity, or other
formation data. Preferably, the sensor is contained in the same
housing as the sensor communications node 184. Indeed, the sensor
may be the same electro-acoustic transducer that enables the
telemetry communication.
The sensor communications node 184 transmits signals from the
sensor 178 as acoustic waves. The acoustic waves are preferably at
a frequency of between about 50 kHz and 500 kHz. The signals are
received by an intermediate communications node 180 that is closest
to the sensor communications node 184. That intermediate
communications node 180, in turn, will relay the signal on to a
next-closest node 180 so that acoustic waves indicative of the
downhole condition are sent from node-to-node. A last intermediate
communications node 180 transmits the signals acoustically to the
topside communications node 182.
Communication may be between adjacent nodes, or it may occasionally
skip a node depending on node spacing or communication range.
Preferably, communication is routed around any nodes that are
broken. Preferably, the number of nodes which transmit a
communication packet is fewer than the total number of nodes
between the sensor node and the topside node in order to conserve
battery power and extend the operational life of the network.
The well site 100 of FIG. 1 also shows a receiver 190. The receiver
190 comprises a processor 192 that receives signals sent from the
topside communications node 182. The signals may be received
through a wire (not shown) such as a co-axial cable, a fiber optic
cable, a USB cable, or other electrical or optical communications
wire. Alternatively, the receiver 190 may receive signals from the
topside communications node 182 wirelessly through a modem, a
transceiver or other wireless communications link. The receiver 190
preferably receives electrical signals via a so-called Class I,
Division 1 conduit, that is, a housing for wiring that is
considered acceptably safe in an explosive environment. In some
applications, radio, infrared or microwave signals may be
utilized.
In any event, the processor 192 may be incorporated into a computer
having a screen. The computer may have a separate keyboard 194, as
is typical for a desk-top computer, or an integral keyboard as is
typical for a laptop or a personal digital assistant. In one
aspect, the processor 192 is part of a multi-purpose "smart phone"
having specific "apps" and wireless connectivity.
It is noted that data may be sent along the nodes not only from the
sensor 178 up to the receiver 190, but also from the receiver 190
down to the sensor 178. This transmission may be of benefit in the
event that the operator wishes to make a change in the way the
sensor 178 is functioning. This is also of benefit when the sensor
178 is actually another type of device, such as an inflow control
device that opens, closes or otherwise actuates in response to a
signal from the surface 101.
FIG. 1 demonstrates the use of a wireless data telemetry system in
connection with a drilling operation. However, the wireless
downhole telemetry system may also be used for a completed
well.
FIG. 2 is a cross-sectional view of an illustrative well site 200.
The well site 200 includes a wellbore 250 that penetrates into a
subsurface formation 255. The wellbore 250 has been completed as a
cased-hole completion for producing hydrocarbon fluids. The well
site 200 also includes a well head 260. The well head 260 is
positioned at an earth surface 201 to control and direct the flow
of formation fluids from the subsurface formation 255 to the
surface 201.
Referring first to the well head 260, the well head 260 may be any
arrangement of pipes or valves that receive reservoir fluids at the
top of the well. In the arrangement of FIG. 2, the well head 260 is
a so-called Christmas tree. A Christmas tree is typically used when
the subsurface formation 255 has enough in situ pressure to drive
production fluids from the formation 255, up the wellbore 250, and
to the surface 201. The illustrative well head 260 includes a top
valve 262 and a bottom valve 264. In some contexts, these valves
are referred to as "master fracture valves." Other valves may also
be used.
It is understood that rather than using a Christmas tree, the well
head 260 may alternatively include a motor (or prime mover) at the
surface 201 that drives a pump. The pump, in turn, reciprocates a
set of sucker rods and a connected positive displacement pump (not
shown) downhole. The pump may be, for example, a rocking beam unit
or a hydraulic piston pumping unit. Alternatively still, the well
head 260 may be configured to support a string of production tubing
having a downhole electric submersible pump, a gas lift valve, or
other means of artificial lift (not shown). The present inventions
are not limited by the configuration of operating equipment at the
surface unless expressly noted in the claims.
Referring next to the wellbore 250, the wellbore 250 has been
completed with a series of pipe strings, referred to as casing.
First, a string of surface casing 210 has been cemented into the
formation. Cement is shown in an annular bore between the bore wall
215 of the wellbore 250 and the casing 210. The surface casing 210
has an upper end in sealed connection with the lower master valve
264.
Next, at least one intermediate string of casing 220 is cemented
into the wellbore 250. The intermediate string of casing 220 is in
sealed fluid communication with the upper master valve 262. Cement
is again shown in a bore 215 of the wellbore 250. The combination
of the casing strings 210, 220 and the cement sheath in the bore
215 strengthens the wellbore 250 and facilitates the isolation of
formations behind the casing 210, 220.
It is understood that a wellbore 250 may, and typically will,
include more than one string of intermediate casing. Some of the
intermediate casing strings may be only partially cemented into
place, depending on regulatory requirements and the presence of
migratory fluids in any adjacent strata.
Finally, a production liner 230 is provided. The production liner
230 is hung from the intermediate casing string 230 using a liner
hanger 232. A portion of the production liner 230 may optionally be
cemented in place. The liner is a string of casing that is not tied
back to the surface 201.
The production liner 230 has a lower end 234 that extends
substantially to an end 254 of the wellbore 250. For this reason,
the wellbore 250 is said to be completed as a cased-hole well.
Those of ordinary skill in the art will understand that for
production purposes, the liner 230 may be perforated or may include
sections of slotted liner to create fluid communication between a
bore 235 of the liner 230 and the surrounding rock matrix making up
the subsurface formation 255.
As an alternative, portions of the liner 230 may include joints of
sand screen (not shown). The use of sand screens with gravel packs
allows for greater fluid communication between the bore 235 of the
liner 230 and the surrounding rock matrix while still providing
support for the wellbore 250. The present inventions are not
limited by the nature of the completion unless expressly so stated
in the claims.
The wellbore 250 also includes a string of production tubing 240.
The production tubing 240 extends from the well head 260 down to
the subsurface formation 255. In the arrangement of FIG. 2, the
production tubing 240 terminates proximate an upper end of the
subsurface formation 255. A production packer 242 is provided at a
lower end of the production tubing 240 to seal off an annular
region 245 between the tubing 240 and the surrounding production
liner 230. However, the production tubing 240 may extend closer to
the end 234 of the liner 230.
It is also noted that the bottom end 234 of the production liner
230 is completed substantially horizontally within the subsurface
formation 255. This is a common orientation for wells that are
completed in so-called "tight" or "unconventional" formations.
However, the present inventions have equal utility in vertically
completed wells or in multi-lateral deviated wells. Further, the
communications nodes 280 themselves may be used in other tubular
constructions such as above-ground, under-ground, or below water
pipelines.
The illustrative well site 200 also includes one or more sensors
290. Here, the sensors 290 are placed at the depth of the
subsurface formation 255. The sensors 290 may be, for example,
pressure sensors, flow meters, or temperature sensors. A pressure
sensor may be, for example, a sapphire gauge or a quartz gauge.
Sapphire gauges are preferred as they are considered more rugged
for the high-temperature downhole environment. Alternatively, the
sensors may be microphones for detecting ambient noise, or
geophones (such as a tri-axial geophone) for detecting the presence
of micro-seismic activity. Alternatively still, the sensors may be
fluid flow measurement devices such as a spinners, or fluid
composition sensors.
It is desirable to send signals about the downhole condition back
to a receiver at the surface 201. As with the well site 100 of FIG.
1, the well site 200 of FIG. 2 includes a telemetry system that
utilizes a series of novel communications nodes. Here, the
communications nodes are placed along the outer diameter of the
string of production tubing 240. These nodes allow for the high
speed transmission of wireless signals based on the in situ
generation of acoustic waves.
The nodes first include a topside communications node 282. The
topside communications node 282 is placed closest to the surface
201. The topside node 282 is configured to receive and/or transmit
signals. The topside communications node 282 should be placed on
the wellhead or next to the surface along the uppermost joint of
casing 210.
The nodes also include a sensor communications node 284. The sensor
communications node 284 is placed closest to the sensors 290. The
sensor communications node 284 is configured to communicate with
the downhole sensor 290, and then send a wireless signal using
acoustic waves.
Finally, the nodes include a plurality of intermediate
communications nodes 280. Each of the intermediate communications
nodes 280 resides between the sensor communications node 284 and
the topside communications node 282. The intermediate
communications nodes 280 are configured to receive and then relay
acoustic signals along the length of the tubing string 240.
Preferably, the intermediate nodes 280 utilize two-way
electro-acoustic transducers to receive and relay mechanical waves.
The intermediate communications nodes 280 preferably reside along
an outer diameter of the casing strings 210, 220, 230.
In operation, the sensor communications node 284 is in electrical
communication with the (one or more) sensors 290. This may be by
means of a short wire, or by means of wireless communication such
as infrared or radio waves. The sensor communications node 284 is
configured to receive signals from the sensors 290, wherein the
signals represent a subsurface condition such as temperature or
pressure. Alternatively, sensor 290 may be contained in the housing
of communications node 284.
The sensor communications node 284 transmits signals from the
sensors 290 as acoustic waves. The acoustic waves are preferably at
a frequency band of about 100 kHz. The signals are received by an
intermediate communications node 280. That intermediate
communications node 280, in turn, will relay the signal on to
another intermediate communications node so that acoustic waves
indicative of the downhole condition are sent from node-to-node. A
last intermediate communications node 280 transmits the signals to
the topside node 282.
The well site 200 of FIG. 2 shows a receiver 270. The receiver 270
comprises a processor 272 that receives signals sent from the
topside communications node 284. The receiver 270 may include a
screen and a keyboard 274 (either as a keypad or as part of a touch
screen). The receiver 270 may also be an embedded controller with
neither screen nor keyboard which communicates with a remote
computer via cellular modem or telephone lines.
The signals may be received by the processor 272 through a wire
(not shown) such as a co-axial cable, a fiber optic cable, a USB
cable, or other electrical or optical communications wire.
Alternatively, the receiver 270 may receive the final signals from
the topside node 282 wirelessly through a modem or transceiver. The
receiver 270 preferably receives electrical signals via a so-called
Class I, Division 1 conduit, that is, a wiring conduit that is
considered acceptably safe in an explosive environment.
FIGS. 1 and 2 present illustrative wellbores 150, 250 having a
downhole telemetry system that uses a series of acoustic
transducers. In each of FIGS. 1 and 2, the top of the drawing page
is intended to be toward the surface and the bottom of the drawing
page toward the well bottom. While wells commonly are completed in
substantially vertical orientation, it is understood that wells may
also be inclined and even horizontally completed. When the
descriptive terms "up" and "down" or "upper" and "lower" or similar
terms are used in reference to a drawing, they are intended to
indicate relative location on the drawing page, and not necessarily
orientation in the ground, as the present inventions have utility
no matter how the wellbore is orientated.
In each of FIGS. 1 and 2, the communications nodes 180, 280 are
specially designed to withstand the same corrosive and
environmental conditions (i.e., high temperature, high pressure) of
a wellbore 150 or 250 as the casing strings, drill string, or
production tubing. To do so, it is preferred that the
communications nodes 180, 280 include sealed steel housings for
holding the electronics.
FIG. 4A is a perspective view of a communications node 400 as may
be used in the wireless data transmission systems of FIG. 1 or FIG.
2 (or other wellbore), in one embodiment. The communications node
400 may be an intermediate communications node that is designed to
provide two-way communication using a transceiver within a novel
downhole housing assembly. FIG. 4B is a cross-sectional view of the
communications node 400 of FIG. 4A. The view is taken along the
longitudinal axis of the node 400. The communications node 400 will
be discussed with reference to FIGS. 4A and 4B, together.
The communications node 400 first includes a housing 410. The
housing 410 is designed to be attached to an outer wall of a joint
of wellbore pipe, such as the pipe joint 300 of FIG. 3. Where the
wellbore pipe is a carbon steel pipe joint such as drill pipe,
casing or liner, the housing is preferably fabricated from carbon
steel. This metallurgical match avoids galvanic corrosion at the
coupling.
The housing 410 is dimensioned to be strong enough to protect
internal electronics. In one aspect, the housing 410 has an outer
wall 412 that is about 0.2 inches (0.51 cm) in thickness. A bore
405 is formed within the wall 412. The bore 405 houses the
electronics, shown in FIG. 4B as a battery 430, a power supply wire
435, a transceiver 440, and a circuit board 445. The circuit board
445 will preferably include a micro-processor or electronics module
that processes acoustic signals. An electro-acoustic transducer 442
is provided to convert acoustical energy to electrical energy (or
vice-versa) and is coupled with outer wall 412 on the side attached
to the tubular body. The transducer 442 is in electrical
communication with at least one sensor 432.
It is noted that in FIG. 4B, the sensor 432 resides within the
housing 410 of the communications node 400. However, as noted, the
sensor 432 may reside external to the communications node 400, such
as above or below the node 400 along the wellbore. In FIG. 4C, a
dashed line is provided showing an extended connection between the
sensor 432 and the electro-acoustic transducer 442.
The transceiver 440 will receive an acoustic telemetry signal. In
one preferred embodiment, the acoustic telemetry data transfer is
accomplished using multiple frequency shift keying (MFSK). Any
extraneous noise in the signal is moderated by using well-known
conventional analog and/or digital signal processing methods. This
noise removal and signal enhancement may involve conveying the
acoustic signal through a signal conditioning circuit using, for
example, a bandpass filter.
The transceiver will also produce acoustic telemetry signals. In
one preferred embodiment, an electrical signal is delivered to an
electromechanical transducer, such as through a driver circuit. In
a preferred embodiment, the transducer is the same electro-acoustic
transducer that originally received the MFSK data. The signal
generated by the electro-acoustic transducer then passes through
the housing 410 to the tubular body (such as production tubing
240), and propagates along the tubular body to other communication
nodes. The re-transmitted signal represents the same sensor data
originally transmitted by sensor communications node 284. In one
aspect, the acoustic signal is generated and received by a
magnetostrictive transducer comprising a coil wrapped around a core
as the transceiver. In another aspect, the acoustic signal is
generated and received by a piezoelectric ceramic transducer. In
either case, the electrically encoded data are transformed into a
sonic wave that is carried through the wall of the tubular body in
the wellbore.
The communications node 400 optionally has a protective outer layer
425. The protective outer layer 425 resides external to the wall
412 and provides an additional thin layer of protection for the
electronics. The communications node 400 is also preferably fluid
sealed with the housing 410 to protect the internal electronics.
Additional protection for the internal electronics is available
using an optional potting material.
The communications node 400 also optionally includes a shoe 500.
More specifically, the node 400 includes a pair of shoes 500
disposed at opposing ends of the wall 412. Each of the shoes 500
provides a beveled face that helps prevent the node 400 from
hanging up on an external tubular body or the surrounding earth
formation, as the case may be, during run-in or pull-out. The shoes
500 may have a protective outer layer 422 and an optional
cushioning material 424 (shown in FIG. 4A) under the outer layer
422.
FIGS. 5A and 5B are perspective views of an illustrative shoe 500
as may be used on an end of the communications node 400 of FIG. 4A,
in one embodiment. In FIG. 5A, the leading edge or front of the
shoe 500 is seen, while in FIG. 5B the back of the shoe 500 is
seen.
The shoe 500 first includes a body 510. The body 510 includes a
flat under-surface 512 that butts up against opposing ends of the
wall 412 of the intermediate communications node 400.
Extending from the under-surface 512 is a stem 520. The
illustrative stem 520 is circular in profile. The stem 520 is
dimensioned to be received within opposing recesses 414 of the wall
412 of the node 400.
Extending in an opposing direction from the body 510 is a beveled
surface 530. As noted, the beveled surface 530 is designed to
prevent the communications node 400 from hanging up on an object
during run-in into a wellbore.
Behind the beveled surface 530 is a flat surface 535. The flat
surface 535 is configured to extend along the drill string 160 (or
other tubular body) when the communications node 400 is attached
along the tubular body. In one aspect, the shoe 500 includes an
optional shoulder 515. The shoulder 515 creates a clearance between
the flat surface 535 and the tubular body opposite the stem
520.
In one arrangement, the communications nodes 400 with the shoes 500
are welded onto an inner or outer surface of the tubular body, such
as wall 310 of the pipe joint 300. More specifically, the body 410
of the respective communications nodes 400 are welded onto the wall
of the tubular body. In some cases, it may not be feasible or
desirable to pre-weld the communications nodes 400 onto pipe joints
before delivery to a well site. Therefore, it is desirable to
utilize a clamping system that allows a drilling or service company
to mechanically connect/disconnect the communications nodes 400
along a tubular body as the tubular body is being run into a
wellbore.
FIG. 6 is a perspective view of a communications node system 600 of
the present invention, in one embodiment. The communications node
system 600 utilizes a pair of clamps 610 for mechanically
connecting an intermediate communications node 400 onto a tubular
body 630.
The system 600 first includes at least one clamp 610. In the
arrangement of FIG. 6, a pair of clamps 610 is used. Each clamp 610
abuts the shoulder 515 of a respective shoe 500. Further, each
clamp 610 receives the base 535 of a shoe 500. In this arrangement,
the base 535 of each shoe 500 is welded onto an outer surface of
the clamp 610. In this way, the clamps 610 and the communications
node 400 become an integral tool.
The illustrative clamps 610 of FIG. 6 include two arcuate sections
612, 614. The two sections 612, 614 pivot relative to one another
by means of a hinge. Hinges are shown in phantom at 615. In this
way, the clamps 610 may be selectively opened and closed.
Each clamp 610 also includes a fastening mechanism 620. The
fastening mechanisms 620 may be any means used for mechanically
securing a ring onto a tubular body, such as a hook or a threaded
connector. In the arrangement of FIG. 6, the fastening mechanism is
a threaded bolt 625. The bolt 625 is received through a pair of
rings 622, 624. The first ring 622 resides at an end of the first
section 612 of the clamp 610, while the second ring 624 resides at
an end of the second section 614 of the clamp 610. The threaded
bolt 625 may be tightened by using, for example, one or more
washers (not shown) and threaded nuts 627.
In operation, a clamp 610 is placed onto the tubular body 630 by
pivoting the first 612 and second 614 arcuate sections of the clamp
610 into an open position. The first 612 and second 614 sections
are then closed around the tubular body 630, and the bolt 625 is
run through the first 622 and second 624 receiving rings. The bolt
625 is then turned relative to the nut 627 in order to tighten the
clamp 610 and connected communications node 400 onto the outer
surface of the tubular body 630. Where two clamps 610 are used,
this process is repeated.
The tubular body 630 may be, for example, a drill string such as
the illustrative drill string 160 of FIG. 1. Alternatively, the
tubular body 630 may be a string of production tubing such as the
tubing 240 of FIG. 2. In any instance, the tubular body 630 is
ideally fabricated from a steel material having a thickness which
contributes to broadening a mechanical response of the
electro-acoustic transducer in the intermediate communications node
400, where the mechanical resonance is at a frequency contained
within the frequency band used for telemetry.
In one aspect, the communications node 400 is about 12 to 20 inches
(0.30 to 0.51 meters) in length as it resides along the tubular
body 630. Specifically, the housing 410 of the communications node
may be 8 to 16 inches (0.20 to 0.41 meters) in length, and each
opposing shoe 500 may be 2 to 5 inches (0.05 to 0.13 meters) in
length. Further, the communications node 400 may be about 1 inch in
width and 1 inch in height. The housing 410 of the communications
node 400 may have a concave profile that generally matches the
radius of the tubular body 630.
A method for transmitting data in a wellbore is also provided
herein. The method preferably employs the communications node 400
and the clamping system 600 of FIG. 6.
FIG. 7 provides a flow chart for a method 700 of transmitting data
in a wellbore. The method 700 uses a plurality of communications
nodes situated along a tubular body to accomplish a wireless
transmission of data along the wellbore. The wellbore penetrates
into a subsurface formation, allowing for the communication of a
wellbore condition at the level of the subsurface formation up to
the surface.
The method 700 first includes running a tubular body into the
wellbore. This is shown at Box 710. The tubular body is formed by
connecting a series of pipe joints end-to-end. The pipe joints are
fabricated from a steel material that is suitable for conducting an
acoustical signal.
The method 700 also includes placing at least one sensor along the
wellbore at a depth of the subsurface formation. This is provided
at Box 720. Here, the sensor may be a pressure sensor, a
temperature sensor, an inclinometer, a logging tool, a resistivity
sensor, a vibration sensor, a fluid density sensor, a fluid
identification sensor, a fluid flow measurement device (such as a
so-called "spinner") or other sensor. The sensor may reside, for
example, along a string of drill pipe as part of a rotary steerable
drilling system. Alternatively, the sensor may reside along a
string of casing within a wellbore. Alternatively still, the sensor
may reside along a string of production tubing or a joint of sand
screen.
The method 700 further includes attaching a sensor communications
node to the tubular body. This is seen at Box 730. The sensor
communications node may be placed either inside or outside of a
tubular body. The sensor communications node is then placed at the
depth of the subsurface formation. The sensor communications node
is in communication with the at least one sensor. This is
preferably a short wired connection or a connection through a
circuit board. Alternatively, the communication could be acoustic
or radio frequency (RF), particularly in the case when the sensor
and communications nodes are not in the same housing. The sensor
communications node is configured to receive signals from the at
least one sensor. The signals represent a subsurface condition such
as temperature, pressure, pipe strain, fluid flow or fluid
composition, or geology.
Preferably, the at least one sensor resides within the housing for
the sensor communications node. The sensor communications node may
alternatively be configured to use the electro-acoustic transducer
as a sensor.
The method 700 also provides for attaching a topside communications
node to the tubular body. This is indicated at Box 740. The topside
communications node is attached to the tubular body proximate the
surface. In one aspect, the topside communications node is
connected to the well head, which for purposes of the present
disclosure may be considered part of the tubular body.
The method 700 further comprises attaching a plurality of
intermediate communications nodes to the tubular body. This is
shown at Box 750. The intermediate communications nodes reside in
spaced-apart relation along the tubular body between the sensor
communications node and the topside communications node. The
intermediate communications nodes are configured to receive and
transmit acoustic waves from the sensor communications node to the
topside node. In one aspect, piezo wafers or other piezoelectric
elements are used to receive and transmit acoustic signals. In
another aspect, multiple stacks of piezoelectric crystals or
magnetostrictive devices are used. Signals are created by applying
electrical signals of an appropriate frequency across one or more
piezoelectric crystals, causing them to vibrate at a rate
corresponding to the frequency of the desired acoustic signal. Each
acoustic signal represents a packet of data comprised of a
collection of separate tones.
In the method 700, each of the intermediate communications nodes
has an independent power source. The independent power source may
be, for example, batteries or a fuel cell. In addition, each of the
intermediate communications nodes has a transducer. The transducer
is preferably an electro-acoustic transducer with an associated
transceiver that is designed to receive the acoustic waves and
produce acoustic waves.
In one aspect, the data transmitted between the nodes is
represented by acoustic waves according to a multiple frequency
shift keying (MFSK) modulation method. Although MFSK is well-suited
for this application, its use as an example is not intended to be
limiting. It is known that various alternative forms of digital
data modulation are available, for example, frequency shift keying
(FSK), multi-frequency signaling (MF), phase shift keying (PSK),
pulse position modulation (PPM), and on-off keying (OOK). In one
embodiment, every 4 bits of data are represented by selecting one
out of sixteen possible tones for broadcast.
Acoustic telemetry along tubulars is characterized by multi-path or
reverberation which persists for a period of milliseconds. As a
result, a transmitted tone of a few milliseconds duration
determines the dominant received frequency for a time period of
additional milliseconds. Preferably, the communication nodes
determine the transmitted frequency by receiving or "listening to"
the acoustic waves for a time period corresponding to the
reverberation time, which is typically much longer than the
transmission time. The tone duration should be long enough that the
frequency spectrum of the tone burst has negligible energy at the
frequencies of neighboring tones, and the listening time must be
long enough for the multipath to become substantially reduced in
amplitude. In one embodiment, the tone duration is 2 ms, then the
transmitter remains silent for 48 milliseconds before sending the
next tone. The receiver, however, listens for 2+48=50 ms to
determine each transmitted frequency, utilizing the long
reverberation time to make the frequency determination more
certain. Beneficially, the energy required to transmit data is
reduced by transmitting for a short period of time and exploiting
the multi-path to extend the listening time during which the
transmitted frequency may be detected.
In one embodiment, an MFSK modulation is employed where each tone
is selected from an alphabet of 16 tones, so that it represents 4
bits of information. With a listening time of 50 ms, for example,
the data rate is 80 bits per second.
The tones are selected to be within a frequency band where the
signal is detectable above ambient and electronic noise at least
two nodes away from the transmitter node so that if one node fails,
it can be bypassed by transmitting data directly between its
nearest neighbors above and below. In one example, the tones can be
approximately evenly spaced in frequency, but the tones may be
spaced within a frequency band from about 50 kHz to about 500 kHz.
More preferably, the tones are evenly spaced in a period within a
frequency band approximately 25 kHz wide centered around or
including 100 kHz.
Preferably, the nodes employ a "frequency hopping" method where the
last transmitted tone is not immediately re-used. This prevents
extended reverberation from being mistaken for a second transmitted
tone at the same frequency. For example, 17 tones are utilized for
representing data in an MFSK modulation scheme; however, the
last-used tone is excluded so that only 16 tones are actually
available for selection at any time.
In one aspect, the tubular body is a drill string. In this
instance, each of the intermediate communications nodes is
preferably placed along an outer diameter of pipe joints making up
the drill string. In another aspect, the tubular body is a casing
string. In this instance, each of the intermediate communications
nodes is placed along an outer surface of pipe joints making up the
casing string. In yet another embodiment, the tubular body is a
production string such as tubing. In this instance, each of the
intermediate communications nodes may be placed along an outer
diameter of pipe joints making up the production string.
In one aspect, the method 700 further includes transmitting a
signal from the topside communications node to a receiver. This is
shown at Box 760. The topside communications node also comprises an
independent power source, meaning that it does not also supply
power to any other intermediate or sensor communications node. The
independent power source may be either internal to or external to
the topside communications node. Further, the topside
communications node has an electro-acoustic transducer designed to
receive the acoustic waves from one or more of the plurality of
intermediate communications nodes, and transmit acoustic waves to
the receiver as a new signal. Preferably, the topside
communications node includes a magnetically activated reed switch
or other means to silence radio transmissions from the node without
opening the Class 1 Div 1 housing.
The communication signal between the topside communications node
and the receiver may be either a wired electrical signal or a
wireless radio transmission. Alternatively, the signal may be an
optical signal. In any instance, the signal represents a subsurface
condition as transmitted by the sensor in the subsurface formation.
The signals are received by the receiver, which has data
acquisition capabilities. The receiver may employ either volatile
or non-volatile memory. The data may then be analyzed at the
surface.
As can be seen, a novel downhole telemetry system is provided, as
well as a novel method for the wireless transmission of information
using a plurality of data transmission nodes. The re-transmission
process that takes place along the nodes not only provides a
mechanism to remove signal noise, but also increases the signal
amplitude. In the system, the repertoire of frequencies used by the
nodes for communication, the amplitude of each frequency, the time
duration for which each frequency is transmitted, and the time
between signals may be optimized to find a balance between data
transmission rate and energy used in data transmission.
In one embodiment, the tubular body is made up of joints of pipe
that form a casing string. At least some of the joints of pipe and
the connected communications nodes are surrounded by a cement
sheath.
While it will be apparent that the inventions herein described are
well calculated to achieve the benefits and advantages set forth
above, it will be appreciated that the inventions are susceptible
to modification, variation and change without departing from the
spirit thereof.
* * * * *
References